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Key Learnings From First 2 Years
of a Full-Field CSS Development in Oman
T
400
A. Injection
350
300
Wellhead Temperature (°C)
he A East Haradh formation
contains a 200-m-thick oil column
of highly viscous oil, with viscosity
ranging from 200 to 400,000 cp.
Because of the high viscosity, first
production was considered possible
only by the use of thermal enhanced-oilrecovery techniques, starting with cyclic
steam stimulation (CSS). This paper
presents key learnings derived during
this initial-operations phase of CSS
in the A East Field, including key trial
results on different well completions
and artificial-lift systems.
B. Soaking
250
C. Free Flow
200
D. Prepare for Production
150
F. Cycle End
100
E. Beam-Pump Production
Overview of Field Startup
In light of the results of a new geochemical characterization study of the crude
extracted from a core, cold production was deemed feasible in the crestal area of the field. Viscosities at the
top of the Haradh were estimated at
200 cp, lower than previously thought,
and progressing cavity pumps (PCPs)
were installed in 32 wells to start a
cold-production phase.
Cold production started in March
2013 and lasted until the end of 2014,
when all wells in the field were converted to CSS. The cold-production period
allowed early depletion of the reservoir
and later improvement in steam injection. A pressure drop of up to 20 bar was
observed, and fluid-level measurement
in the wells and PCP performance suggested good pressure communication between the wells.
Despite some early challenges, first
CSS production was promising and, with-
50
0
0
25
50
75
100
125
150
175
200
225
250
Days
Fig. 1—Typical CSS cycle phases in an A East well.
in a few months, was ramped up to 70%
of the targeted CSS field peak oil rates.
Overview of CSS Performance
A typical CSS cycle in an A East well is
shown in Fig. 1, using the wellhead temperature sensor as an indicator. The
cycle starts with the injection phase for
several weeks (initially 4 to 6). After
that, the well is closed for a soaking period of a few days and then opened for
free flow, which lasts for up to 3 weeks.
The well is intervened with a flush-by
unit (FBU) to prepare for production,
followed by starting the beam pump. At
This article, written by Special Publications Editor Adam Wilson, contains
highlights of paper SPE 179833, “Key Learnings From First 2 Years of a FullField CSS Development in Oman,” by Solenn Bettembourg, Steve Holyoak,
Abdullah Alwazeer, Mohammed Manhali, Mohammed Rawahi, and Amur
Habsi, Petroleum Development Oman, prepared for the 2016 SPE EOR Conference
at Oil and Gas West Asia, Muscat, Oman, 21–23 March. The paper has not been
peer reviewed.
the end of the production cycle, the well
is stopped on the basis of end-of-cycle
criteria and intervened again to prepare
the well for steam injection for the subsequent cycle. The overall cycle duration is typically between 100 and 300
days and is dependent on the performance of the well with respect to preset
operating envelopes.
Wellhead temperature in the production phase starts high in the beginning
of the CSS cycle and then declines with
time. From actual valid well-test data,
there is a clear declining trend of the
liquid and oil rates associated with and
linked to the drop of the wellhead temperature. This is mainly because of the
cooling effect after back producing the
injected fluid. Hence, the pump efficiency deteriorates at lower temperatures because of the high oil viscosity,
and this is observed in the reduction of
liquid/oil with time in the productiontest data.
For a limited time, the complete paper is free to SPE members at www.spe.org/jpt.
64
JPT • MARCH 2017
Operating the CSS
in A East Field
Artificial Lift Challenges and Mitigations. The initial plan for A East Field
was for development with steam bypass pumps (SBPPs). However, design
constraints led the team to operate the
wells as dedicated steaming through tubing without the use of the SBPPs, followed by reinstalling rods and pumps
for the production phase. The new approach increased the demand for resources. The selected artificial lift covers a reasonable production range but
has some limitations, especially in the
high-viscosity range.
SBPP—Management of Change and
Effect on CSS Operation. In the initial
plan, all CSS operations were planned
to use the SBPP. Because of the significant depth of the reservoir and the need
for minimal steam-quality loss downhole, the proposed efficient approach
using the SBPP was changed. The change
involved using vacuum-insulated tubing (VIT), which provided better steamquality preservation. The thermal expansion of the VIT did not match the rod
strings, and the added length needed
to pull out the rods at surface made the
SBPP less favorable for this application.
An alternative plan was implemented
to make use of the VIT benefits and operate CSS with dedicated injection- and
production-mode completions. The early
conversion took significant time. All operating procedures for hoist and FBU had
to be adjusted for the changes of operation, including a new standardized killing procedure.
Beam-Pump Operating Envelope for
Highly Viscous Oil. Beam pumps in A
East Field can operate with oil viscosity up to 5,000 cp. This limitation becomes an issue during two periods of the
cycle—pump startup after conversion
when the well is killed and end of production in a cycle.
Start of production was challenging
for some wells, and a typical dyno card
confirms the pump’s inability to close
both standing and traveling, likely related to viscosity.
To mitigate the challenges of starting
up the pumps, the following methodologies were tested:
JPT • MARCH 2017
◗
Solvent injection (light-crude
injection)
◗ Hot-water circulation in the annulus
◗ Prolonged shut-in time after killing
the wells, to allow the hot fluids
from the near-wellbore region to
warm the well
◗ Slow startup of the wells
The most reliable method was starting at very low speeds for 24 hours. Although the low speeds are not recommended because of gearbox-lubrication
concerns, it is set for a maximum of 24
hours until the fluid temperatures rise
and viscosity decreases for improved fillage and pump performance. For wells
that were extremely difficult to start even
at lower speeds, annulus steam injection at low temperature and pressure was
deemed effective (approximately 200°C
and 3000 kPa).
The end of the production cycle also
presented a challenge as the well cools
down and viscosity increases. This viscosity increase affected pump performance. A review on artificial-lift selection for future development is planned,
to address the current limitations.
Well- and ReservoirManagement Challenges
of CSS Operations
CSS operations require a high level of
planning and managing of interfaces. In
the A East Field, the wells are fully converted. The full production completion
is pulled out, stored, and reinstalled later
after steam injection has occurred. To
maximize the efficiency of a CSS cycle,
the full process was mapped, the interfaces between teams were defined, and
roles and responsibilities were assigned.
That included the redefinition of custodianship for the material by the wellintervention units and the reinforcement
of tracking pump tear down and reports.
The change had to be made to accommodate the operational shift from SBPP to
dedicated modes.
Some challenges were experienced
during surveillance activities. The activities were affected by the high column of
viscous fluids in the well, made worse by
the well-killing procedure. This problem
was mitigated by changing the intervention times to be approximately 3 days
after the injection-termination date. This
allowed for logging while the well was hot
and at much lower viscosity and for standardizing the acquisition of the logs for
time-lapse analysis.
Optimization:
Future of CSS in A East
Optimization in a CSS field is extremely
challenging because it requires the integration of different parameters and is
highly dependent on where the well is in
the cycle. The team successfully managed
more than 700 optimization changes in A
East in 2015, requiring significant analysis time and decision making in a dynamic system.
In order to minimize the time spent
on optimization and reduce reaction
times, all wells in the A East Field were
equipped with variable-speed drives.
The wells can self-optimize. In addition,
there is an ongoing trial in four wells
known as the Beam Lift Automated Delivery Evolution (BLADE) project. The programmable logic looks at the preset dead
band variable and increases or decreases
strokes per minute, depending on changing conditions. The typical duration to
review and execute an optimization request is approximately 1 week; however,
the BLADE well can achieve the change in
minutes. Implementation of the BLADE
project is anticipated on all the wells in A
East in 2016. The project team is looking
into linking the optimization signal to the
well-test fieldware, to ensure the capture
of the optimized volumes.
Conclusions
The CSS development in A East Field has
been in operation for almost 2 years, and
significant learning has been achieved
and modifications have been taken on
board to optimize ongoing performance.
A number of challenges are still being
faced, but, within this short period of
time, the team has achieved a steep production increase and has streamlined the
overall CSS well-conversion process to
maximize the efficiency of the CSS planning and operations. New technologies
are supporting the management of the
wells and the integration of production
data with new geological and structural
insights from the latest seismic interpretation. Taken together, these efforts are
paving the way to continued success and
providing the confidence to mature plans
for further field expansion. JPT
65
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